Uranium Markets

Production from world uranium mines now supplies 90% of the requirements of power utilities.

Primary production from mines is supplemented by secondary supplies, formerly most from ex-military material but now the products of recycling and stockpiles built up in times of reduced demand.

World mine production has expanded significantly since about 2005.

All mineral commodity markets tend to be cyclical, i.e. prices rise and fall substantially over the years, but with these fluctuations superimposed on long-term trend decline in real prices, as technological progress reduces production cost at mines. In the uranium market, however, high prices in the late 1970s gave way to depressed prices in the whole of the period of the 1980s and 1990s, with spot prices below the cost of production for all but the lowest cost mines. Spot prices recovered from 2003 to 2009, but have been weak since then.

The quoted spot prices through to about 2007 applied only to day-to-day marginal trading and represented a small portion of supply, though since 2008 the proportion has approximately doubled, to about one-quarter in the last decade. Most trade is via 3-15 year term contracts with producers selling directly to utilities at a significantly higher price than the spot market, reflecting the security of supply.* The specified price in these contracts is, however, often related to the spot price at the time of delivery. However, as production has risen much faster than demand, fewer long-term contracts are being written.

* In June 2017 the spot price was $20.10 per pound U3O8, the long-term price quoted by UxC was $32.

In 2000, primary market participants – utilities and producers – accounted for 95% of the spot market. That share decreased to two-thirds by 2005 and one-third by 2011 and it has remained at 30-40% since. The rest comes from the financial community, namely traders and financiers who have moved in on the market, binging greater liquidity and efficiency.

The reasons for fluctuation in mineral prices relate to demand and perceptions of scarcity. The price cannot indefinitely stay below the cost of production (see below), nor will it remain at very high levels for longer than it takes for new producers to enter the market and anxiety about supply to subside.

Graph courtesy of UxC

Note that the Euratom long-term price is the average price of uranium delivered into the EU that year under long term contracts. It is not the price at which long-term contracts are being written in that year.

Demand

About 445 reactors with combined capacity of over 390 GWe, require some 75,000 tonnes of uranium oxide concentrate containing 63,000 tonnes of uranium (tU) from mines (or the equivalent from stockpiles or secondary sources) each year. This includes initial cores for new reactors coming online. The capacity is growing slowly, and at the same time the reactors are being run more productively, with higher capacity factors, and reactor power levels. However, these factors increasing fuel demand are offset by a trend for increased efficiencies, so demand is dampened – over the 20 years from 1970 there was a 25% reduction in uranium demand per kWh output in Europe due to such improvements, which continue today.

Each GWe of increased new capacity will require about 150 tU/yr of extra mine production routinely, and about 300-450 tU for the first fuel load.

Fuel burnup is measured in MW days per tonne U, and many utilities are increasing the initial enrichment of their fuel (eg from 3.3 towards 5.0% U-235) and then burning it longer or harder to leave only 0.5% U-235 in it (instead of twice this).

Source: Uranium Institute (now World Nuclear Association) 1992

The graph from Sweden's Oskarsamn 3 reactor shows that with increasing fuel burn-up from 35,000 to 55,000 MWd/t a constant amount of uranium is required per unit of electrical output, and energy used (indicated by SWU) for increased levels of enrichment increases slightly. However, the amount of fabricated fuel used in the reactor drops significantly due to its higher enrichment and burn-up.

Generally, utilities have pursued higher enrichment and burn-ups, and when uranium prices were high they specified low tails assay from enrichment, to get more fuel from it, so that significantly less natural uranium feed was required. However, more enrichment energy was then needed. There is a clear trade-off between energy input to enrichment and uranium input.

Because of the cost structure of nuclear power generation, with high capital and low fuel costs, the demand for uranium fuel is much more predictable than with probably any other mineral commodity. Once reactors are built, it is very cost-effective to keep them running at high capacity and for utilities to make any adjustments to load trends by cutting back on fossil fuel use. Demand forecasts for uranium thus depend largely on installed and operable capacity, regardless of economic fluctuations. However, this picture is complicated by policies which give preferential grid access to subsidised wind and solar PV sources.

Looking ten years ahead, the market is expected to grow significantly. The WNA 2015 Nuclear Fuel Report reference scenario (post Fukushima accident) shows a 26% increase in uranium demand over 2015-25 (for a 30% increase in reactor capacity – many new cores will be required). Demand thereafter will depend on new plant being built and the rate at which older plant is retired – the reference scenario has a 22% increase in uranium demand for the decade 2020 to 2030. Licensing of plant lifetime extensions and the economic attractiveness of continued operation of older reactors are critical factors in the medium-term uranium market. However, with electricity demand by 2040 expected (by the OECD's International Energy Agency in its World Energy Outlook 2016 report) to increase 67% from that of 2014, there is plenty of scope for growth in nuclear capacity in a world concerned with limiting carbon emissions.

Supply

Mines in 2016 supplied some 73,000 tonnes of uranium oxide concentrate (U3O8) containing 62,027 tU, almost all the utilities' annual requirements (see also information paper on World Uranium Mining). The balance is made up from secondary sources including stockpiled uranium held by utilities, and in the last few years of low prices those civil stockpiles have been built up again following their depletion about 1990-2005. At the end of 2014 they were estimated at almost 100,000 tU in Europe and the USA, about 74,000 tU in China, and about 45,000 tU in the rest of east Asia.

The perception of imminent scarcity drove the spot price for uncontracted sales to over US$ 100 per pound U3O8 in 2007 but it has settled back to under $20 over the four years to mid-2017. Most uranium however is supplied under long-term contracts and the prices in new contracts have, in the past, reflected a premium of at lease $10/lb above the spot market.

Note that at the prices which utilities are likely to be paying for current delivery, only one-third of the cost of the fuel loaded into a nuclear reactor is the actual ex-mine (or other) supply. The balance is mostly the cost of enrichment and fuel fabrication, with a small element for uranium conversion.

The above graph, from CRU Strategies, shows a cost curve for world uranium producers in 2010, and suggests that for 53,500 tU/yr production from mines in that year, and for 56,200 tU production in 2014, US$40/lb is a marginal price.

With the main growth in uranium demand being in Russia and China, it is noteworthy that the vertically-integrated sovereign nuclear industries in these countries (and potentially India) have sought equity in uranium mines abroad, bypassing the market to some extent. Strategic investment in uranium production, even if it is not lowest-cost, has become the priority while world prices have been generally low. Russia’s ARMZ has bought Canada-based Uranium One, with 2013 production of over 5000 tU in several countries, and China’s CGNPC-URC has bought a majority share of the large Husab project in Namibia, with potential production of 5770 tU/yr (some to be sold into world markets). China’s SinoU (CNNC) has bought a 25% share in Langer Heinrich in Namibia, giving it over 500 tU/yr, and is bidding for more. It also has 37.5% of the SOMINA joint venture in Niger, entitling it to over 1800 tU/yr in future, and up to 49% of Zhalpak JV in Kazakhstan, adding another 500 tU/yr.

Supply from elsewhere

As well as existing and likely new mines, nuclear fuel supply may be from secondary sources including:

Recycled uranium and plutonium from used fuel, as mixed oxide (MOX) fuel.

Re-enriched depleted uranium tails.

Ex-military weapons-grade uranium, blended down.

Civil stockpiles.

Ex-military weapons-grade plutonium, as MOX fuel.

Commercial reprocessing plants are operating in France and UK, and another is due to start up in Japan. Some reprocessing occurs in Russia. The product from these re-enters the fuel cycle and is fabricated into fresh mixed oxide (MOX) fuel elements. About 200 tonnes of MOX fuel is used each year, equivalent to less than 2000 tonnes of U3O8 from mines.

Military uranium for weapons was enriched to much higher levels than that for the civil fuel cycle. Weapons-grade material is about 97% U-235, and this can be diluted about 25:1 with depleted uranium (or 30:1 with enriched depleted uranium) to reduce it to about 4%, suitable for use in a power reactor. From 1999 to 2013 the dilution of 30 tonnes per year of such material displaced about 9720 tonnes U3O8 per year of mine production. (see also paper on Military Warheads as a source of Nuclear Fuel).

The following graph gives an historical perspective, showing how early production went first into military inventories and then, in the early 1980s, into civil stockpiles. It is this early production which has made up the shortfall in supply from mines since the mid 1980s. However, the shortfall is diminishing towards the level of continuing secondary supplies.

The USA and Russia have agreed to dispose of 34 tonnes each of military plutonium by 2014. Most of it is likely to be used as feed for MOX plants, to make about 1500 tonnes of MOX fuel which will progressively be burned in civil reactors.

The following graph (WNA 2015 Nuclear Fuel Report reference scenario) suggests how these various sources of supply might look in the decades ahead: